In an oil or gas well, the bottom hole pressure and the gas to liquid ratio will eventually not support a natural flow therefrom. The well operator at that time must select an artificial lift to remove fluid from the well so as to resume production. A plunger lift is a form of artificial lift which may be utilized in maintaining production levels and stabilizing the rate of decline of production of oil and gas from a well.
Plunger lift is an established method for enhancing the removal of liquids from a well that is producing at least some natural gas. The liquids may be oil, hydrocarbon condensates, water, or any combination thereof. If permitted to accumulate in a well bore, these liquids build up to create a hydrostatic back pressure against the formation, which in turn reduces production and may ultimately stop production completely.
As the oil or gas flow rate and pressure decline in a well, the lifting efficiency declines. The well then may begin to “load up” and “log off”. This means that gas being produced into the well bore can no longer carry the fluid produced to the surface. One reason for this is that, as liquid comes in contact with the wall of the production string or tubing, friction will occur. The velocity of that liquid is thus reduced and some of the liquid adheres to the tubing wall, creating a film of liquid on that tubing wall. Thus, that liquid does not reach the well head at the surface.
Additionally, as the flow continues to slow, the gas phase can no longer support liquid in either slug form or droplet form. This liquid along with the liquid film on the sides of the tubing begins to fall back to the bottom of the well. In a very aggravated situation there will be liquid in the bottom of the well with only a small amount of gas being produced at the surface. The produced gas must bubble through the liquid at the bottom of the well and then flow to the surface. Because of the low velocity, very little liquid if any is carried to the surface of the well by the gas.
The corresponding head of liquid in the bottom of the well exerts a back pressure against the producing formation, with a value corresponding to the vertical elevation of the liquid in the well, effectively terminating the well's ability to produce. A properly applied plunger lift system is able to bring such a well back to life and make it profitable.
A plunger lift system permits the well to be opened and closed so as to generate a sufficient pressure permitting the well to flow into the flow line. The plunger travels freely back and forth within the vertical tubing string, from the bottom of the well to the surface and back to the bottom. The plunger is used as a mechanical interface between the gas phase and the fluid phase in the well. When the well is closed at the surface, the plunger rests at the bottom of the well on top of a spring assembly. Pressure within the well rises as gas enters the well. When the well is opened at the surface, with all production being through the tubing, the well begins to flow and the pressure in the tubing decreases. Because the trapped gas in the casing/tubing annulus remains at a higher pressure than the tubing, the differential pressure between the two increases. The liquid level in the annulus decreases as the liquid is pushed downward where it “U tubes” into the tubing. The mechanical tolerance between the outside diameter of the plunger and the inside of the tubing leaves sufficient space for the liquid to bypass the plunger, allowing the plunger to remain initially resting on the bottom. Eventually gas within the tubing causes the plunger to move up the tubing string carrying the fluid load on top. A small amount of gas will bypass the plunger. This is useful as it scours the plunger and the tubing wall of fluid keeping all the fluid on top of the plunger. If the system has been properly engineered, virtually all the liquid can be removed from the well to permit the well to flow at the lowest production pressure possible. The use of such a plunger in the tubing minimizes any fluid fallback over the entire length of the tubing, irrespective of the depth of the well. Such a well may be operated at a lower bottom hole pressure since substantially all the liquid is removed from the well bore, thus enhancing its production.
In some cases, a plunger having a bypass valve that is open when the plunger is falling but closed when the plunger is rising in the well may be used. The bypass valve permits fluid to flow through the body of the plunger when open, and thus facilitates more rapid descent of the plunger within the well, avoiding the need to shut in the well when the plunger is falling. However, when closed, the bypass valve prevents fluid flow through the body of the plunger. With the bypass valve closed when the plunger is rising, the plunger can still be used to perform artificial lift.
A functional plunger lift apparatus requires sufficient gas to drive the system. A plunger lift apparatus will not work in oil wells that are producing no gas. As used herein, a “gas producing well” means an oil or gas well that is producing a sufficient quantity of gas for the implementation of a plunger lift system.
An industry misconception exists as to how much gas and pressure is required to successfully operate a plunger lift system. Because of this misconception, many wells have been placed on more expensive forms of artificial lift, such as pumping units or the like, than are really needed. As a result, optimum output has not been achieved, and capital expenditures have run much higher than necessary.
Generally accepted operating procedures suggest that a plunger lift should be operated at a lift speed in the range of approximately 750 feet per minute. If the well has too little pressure, for example so that the plunger is travelling at less than approximately 500 feet per minute, fluid could slip around the plunger, potentially preventing it from rising. Conversely, if the well has too much pressure, the plunger will ascend too quickly, for example at a rate of greater than 1000 feet per minute, potentially causing damage to surface equipment due to the significant amount of kinetic energy that must be dissipated when the plunger arrives at the surface.
There remains a need for more efficient plungers and plungers that can be operated at higher velocities and/or with less risk of damage to surface equipment.
The foregoing examples of the related art and limitations related thereto are intended to be illustrative and not exclusive. Other limitations of the related art will become apparent to those of skill in the art upon a reading of the specification and a study of the drawings.